Process control systems, like those used in chemical and petroleum processes, typically include one or more process controllers communicatively coupled to at least one host or operator workstation and to one or more field devices via analog, digital, or combined analog/digital buses.
A field device generally is or includes an actuator, sensor, or some combination thereof. Field devices perform functions within the process plant, such as opening or closing valves and measuring process parameters. Example field devices include valves, valve positioners, switches, pumps, and transmitters (e.g., for transmitting measurements obtained via temperature, pressure, or flow rate sensors). Field devices may be communicatively linked to process controllers and/or other field devices via wireless or wired links, and may communicate according to various protocols.
The process controllers (sometimes referred to as “controllers”) receive signals indicative of process measurements made by the field devices and/or other information pertaining to the field devices, use this information to implement control routines, and subsequently generate control signals that are sent over buses or other communication channels to control the operation of the field devices. When the controller executes one or more of the control routines, the controller transmits to a field device a control signal (i.e., control output) based on: (i) one or more received control inputs (e.g., one or more received signals indicative of process measurements made by field devices and/or other information pertaining to the field devices), and (ii) the logic of the one or more control routines.
With the information collected from the field devices and process controllers, an operator or a technician can execute one or more applications at an operator workstation that perform any desired function with respect to the process, such as, for example, configuring the process, viewing the current state of the process, and/or modifying the operation of the process.
As noted, field devices may be configured to communicate with controllers and/or other field devices according to various communication protocols. In traditional 4-20 mA systems, a field device communicates with a controller by way of a current loop (e.g., one or more conductive wires) carrying a 4-20 mA signal indicative of a measurement or control command. For example, a level transmitter may sense a tank level, transmit a current signal corresponding to that measurement (e.g., a 4 mA signal for 0%, a 12 mA signal for 50%, and 20 mA for 100%). The controller receives the current signal, determines the tank level measurement based on the current signal, and takes some action based on the tank level measurement (e.g., opening or closing an inlet valve). Traditional 4-20 mA systems are popular in the industry due to the simplicity and effectiveness of the design. Unfortunately, traditional 4-20 mA current loops can only transmit one particular process signal. Thus, a set-up including a control valve and a flow transmitter on a pipe carrying material may require three separate current loops: one for carrying a 4-20 mA signal indicative of control command for the valve (e.g., move the valve to 60% open); a second for carrying a 4-20 mA signal indicative of the valve's actual position (e.g., so that the controller knows the degree to which the valve has responded to control commands); and a third for carrying a 4-20 mA signal indicative of a measured flow. As a result, a traditional 4-20 mA set-up in a plant that has a large number of field devices may require extensive wiring, which can be costly and can lead to complexity when setting up and maintaining the communication system.
More recently, there has been a move within the process control industry to implement digital communications within the process control environment. For example, the Highway Addressable Remote Transmitter (HART®) protocol uses the loop current magnitude to send and receive analog signals, but also superimposes a digital carrier signal on the current loop signal to enable two-way field communication with smart field instruments. As another example, the FOUNDATION Fieldbus® protocol, provides all digital communications on a two-wire bus associated with an all-digital I/O communication network.
These digital communication protocols generally enable more field devices to be connected to a particular bus, support more and faster communication between the field devices and the controller and/or allow field devices to send more and different types of information, such as information pertaining to the status and configuration of the field device itself, to the process controller. Furthermore, these standard digital protocols enable field devices made by different manufacturers to be used together within the same process control network.
Regardless of the communication protocol utilized, field devices may require on-site setup, configuration, testing, and maintenance. For example, before a field device can be installed at a particular location at a process control plant, the field device may need to be programmed and may then need to be tested before and after the field device is installed. Field devices that are already installed may also need to be regularly checked for maintenance reasons or, for example, when a fault is detected and the field device needs to be diagnosed for service or repair. Generally speaking, configuration and testing of field devices are performed on location using a handheld, portable maintenance tool. Because many field devices are installed in remote, hard-to-reach locations, it is more convenient for a user to test the installed devices in such remote locations using a handheld, portable tool rather than using a full configuration and testing device, which can be heavy, bulky, and non-portable, generally requiring the installed field device to be transported to the site of the diagnostic device.
In the case in which a field device is at least partially operational and supplied with power via a local bus, a handheld maintenance tool, such as a portable testing device (“PTD”), can connect to a communication terminal of the field device to run a diagnostic routine. Generally, the field device and the PTD communicate over a two-wire or a four-wire communication connection or line, typically referred to as a bus. It is known to use a handheld device to connect to, for example, a FOUNDATION Fieldbus® or a HART® communication line or other communication bus to communicate with devices connected to that communication line or bus.
In some cases, testing a field device on location may not be possible unless power is supplied to the field device. This may occur, for example, when there is a power outage, when there is a power issue localized to the field device itself, or when one or more field devices are offline, i.e., in fault situations. Generally, power may be provided to the field device by connecting the field device to a power source via a two-wire power line. For example, FOUNDATION Fieldbus® devices are powered via the same terminals used for communicating with the FOUNDATION Fieldbus® device. However, portable power considerations and Intrinsic Safety (“IS”) standards restrict the manner in which power can be provided to a field device, especially when the field device is installed in a critical or dangerous process control system in the field.
In some cases, Intrinsic Safety (“IS”) standards restrict the manner in which power and other communication signals can be provided to a field device, especially when the field device is installed in a critical or dangerous process control system in the field. Generally, higher voltages are used for providing power to the field devices than the voltages that are used for communicating with the field devices. Additionally, certain safety measures must be implemented before powering a field device in the field. In particular, according to IS guidelines, a technician cannot switch on the power of a field device within the field device itself and cannot use devices that generate voltages over certain predetermined levels.
The IS guidelines prohibit internal power switching and generation of larger voltages because field devices are often installed in proximity to volatile substances or volatile processes, and thus there is higher possibility of causing an explosion by arcing or generating sparks when a high voltage or a power connection is applied to the field device. For reference, an internal switch may be considered any switch that is integrally connected within or physically housed within a field device and/or that is fixed to the field device. Accordingly, the technician servicing the field device cannot use or install a switch within the field device to switch on the power to the device from a provisioned or redundant power line.
Related IS guidelines also advise against switching on power within a PTD that is connected to a field device and that is located within a vicinity of the field device. IS standards generally require manual intervention when applying power to a non-operating or a non-powered field device installed in the field. Although it may be desirable to configure existing PTDs with automatic power functions for powering a field device, this configuration is generally prohibited under the IS standards, especially when providing higher power signals to the field devices for powering the field devices or for testing purposes.
To comply with IS standards, some existing PTDs include an interface with four connection ports for coupling four lines or wires between the PTD and a field device undergoing testing. Generally, a first pair of lines is used for transmitting communication signals at a first voltage range and a second pair of lines is used for powering the field device at a second and higher voltage or voltage range. The first pair of lines is primarily used whenever the field device is undergoing testing, and the second pair of lines/wires is used only when power is needed to be provided to the field device to enable the field device to execute a function (e.g., a test function or a configuration function).
In this manner, additional power to the field device undergoing testing always requires manual intervention that includes connecting additional wires between the field device and the PTD. In short, IS standards have generally limited the development of portable field device testing equipment to require two separate sets of lines or lead sets and three or four ports for connecting a field device to the portable testing equipment.
Installing and maintaining instruments in a typical process plant requires multiple portable tools, such as a communicator for initial set-up and configuration, a calibrator for verification and adjustment of instrument output, and a digital multi-meter for troubleshooting of loop wiring, connections, power supply, and the instrument itself. For example, maintaining rotating equipment (e.g. motors, pumps, and generators) may require additional tools for collecting and analyzing vibration data used to detect impending failure.
The potential presence of explosive gasses or dusts often pose additional requirements that these portable tools be tested and certified by agencies such as Factory Mutual or Canadian Standards Association, in order to be certified as safe for use in hazardous areas, such as the IS standards discussed above. As a result, technicians often need to acquire and/or carry multiple specialized portable tools into the plant in order to perform the required work.
When a user, such as a service technician, performs maintenance testing and/or communications with a field device along a digital process control system, a handheld maintenance tool is typically electrically connected to an electrical loop or bus for data and/or power or directly to a field device. The maintenance tool initially attempts to communicate with the field device, such as by sending and/or receiving digital communication signals along the loop or bus. If the electrical loop or bus is in proper operating condition, the communications signals may be sent and/or received without problem. However, if the electrical loop or bus or the field device contains an electrical fault, such as a short or a break, communications may be impeded, and it may be necessary to diagnose the loop, bus, and/or field device to identify the fault.
In the past, when such a fault was identified, a second, separate loop diagnostics tool would be used to test the lines. This would require the technician to carry a second tool and/or require the technician to go get a second tool. Further, if the device was located in a hazardous area (i.e., in a potentially explosive atmosphere), the technician would need to make sure to have an intrinsically safe loop diagnostics tool. This is necessary because a loop diagnostics tool frequently includes a multi-meter or similar device that emits a power level electrical current to the electrical lines being tested.
Maintenance technicians in process industries perform a wide variety of tasks including installation of instruments, configuration/set-up, calibration, data collection, and troubleshooting of instruments and measurement loops. Performance of these tasks require a myriad of ever-changing portable tools, each with unique user interfaces, menus, and displays.
In the past, although there have been intrinsically safe maintenance tools that communicate with these digital process control system field devices, these maintenance tools have not had the ability to also provide intrinsically safe loop diagnostics. It would be advantageous to reduce the number of tools that the maintenance technician needs to carry and work with in the process plant while installing and/or otherwise working on field devices in the process system.
In the presence of flammable materials or explosive gasses an incorrect connection may cause damage to a process control device. By safely guiding a technician through the connection process and performing connection steps in a safe and proper way, intrinsically safe maintenance tools improve the overall reliability and safety of process control systems.
Furthermore, by providing tools that allow a variety of functions to coexist within the same device, such as communications, process measurements, supply of power, etc. maintenance tools improve the reliability and efficiency of maintenance events. By automating detection, measurement, and mitigation functions and having a variety of tools at hand in the same device, the tool eliminates possible sources of erroneous maintenance procedures, improving the overall safety of the process control system.